1. Field of the Invention
This invention relates to sealing elements used in drilling wells.
2. Description of Related Art
Sealing elements have been used in rotating control devices (RCDs) for many years in the drilling industry. Passive sealing elements, such as stripper rubber sealing elements, can be fabricated with a desired stretch-fit. An example of a proposed stripper rubber sealing element is shown in U.S. Pat. No. 5,901,964. A stripper rubber sealing element may be attached with a rotatable internal bearing member of an RCD to seal around the outside diameter of an inserted tubular to rotate with the tubular during drilling. The tubular may be slidingly run through the RCD as the tubular rotates or when the tubular, such as a drill string, casing, coil tubing, or any connected oilfield component, is not rotating. Examples of some proposed RCDs are shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181.
RCDs have been proposed with a single stripper rubber seal element, as in U.S. Pat. Nos. 4,500,094 and 6,547,002; and Pub. No. US 2007/0163784, and with dual stripper rubber sealing elements, as in the '158 patent, '444 patent and the '181 patent, and U.S. Pat. No. 7,448,454. The wellbore pressure in the annulus acts on the cone shaped stripper rubber sealing element with vector forces that augment a closing force of the stripper rubber sealing element around the tubular. U.S. Pat. No. 6,230,824 proposes two opposed stripper rubber sealing elements, the lower sealing element positioned axially downward, and the upper sealing element positioned axially upward (see FIGS. 4B and 4C of '824 patent).
Unlike a stripper rubber sealing element, an active sealing element typically requires a remote-to-the-tool source of hydraulic or other energy to open or close the sealing element around the outside diameter of the tubular. An active sealing element can be deactivated to reduce or eliminate the sealing forces of the sealing element with the tubular. RCDs have been proposed with a single active sealing element, as in the '784 publication, and with a stripper rubber sealing element in combination with an active sealing element, as in U.S. Pat. Nos. 6,016,880 and 7,258,171 (both with a lower stripper rubber sealing element and an upper active sealing element), and Pub. No. US 2005/0241833 (with a lower active sealing element and an upper stripper rubber sealing element).
A tubular typically comprises sections with varying outer surface diameters. The RCD sealing element must seal around all of the rough and irregular surfaces of the components of the tubular, such as a hardening surface (as proposed in U.S. Pat. No. 6,375,895), drill pipe, tool joints, drill collars, and other oilfield components. The continuous movement of the tubular through the sealing element while the sealing element is under pressure causes wear of the inwardly facing sealing surface of the sealing element.
When drilling with a RCD having dual independent annular sealing elements, the lower of the two sealing elements is typically exposed to the majority of the pressurized fluid and cuttings returning from the wellbore, which communicate with the lower surface of the lower sealing element body. The upper sealing element is exposed to the fluid that is not blocked by the lower sealing element. When the lower sealing element blocks all of the pressurized fluid, the lower sealing element is exposed to a significant pressure differential across its body since its upper surface is essentially at atmospheric pressure when used on land or atop a riser. The highest demand and wear on the RCD sealing elements occurs when tripping the tubular out of the wellbore under high pressure.
American Petroleum Institute Specification 16RCD (API-16RCD) entitled “Specification for Drill Through Equipment—Rotating Control Devices,” First Edition,® February 2005 American Petroleum Institute, proposes standards for safe and functionally interchangeable RCDs. The requirements for API-16RCD must be complied with when moving the drill string through an RCD in a pressurized wellbore. The sealing element is inherently limited in the number of times it can be fatigued with larger diameter tool joints that pass under high differential pressure conditions. Of course, the deeper the wellbores are drilled, the more tool joints that will be stripped through a sealing element, some under high pressure.
RCDs have been proposed in the past to be positioned with marine risers. An example of a marine riser and some of the associated drilling components is proposed in U.S. Pat. Nos. 4,626,135 and 7,258,171. U.S. Pat. No. 6,913,092 proposes a seal housing with a RCD positioned above sea level on the upper section of a marine riser to facilitate a mechanically controlled pressurized system. U.S. Pat. No. 7,237,623 proposes a method for drilling from a floating structure using an RCD positioned on a marine riser. U.S. Pat. Nos. 6,470,975; 7,159,669; and 7,258,171 propose positioning an RCD assembly in a housing disposed in a marine riser. Also, an RCD has also been proposed in U.S. Pat. No. 6,138,774 to be positioned subsea without a marine riser.
Latching assemblies have been proposed in the past for positioning an RCD. U.S. Pat. No. 7,487,837 proposes a latch assembly for use with a riser for positioning an RCD. Pub. No. US 2006/0144622 proposes a latching system to latch an RCD to a housing. Pub. No. US 2008/0210471 proposes a docking station housing positioned above the surface of the water for latching with an RCD. Pub. No. US 2009/0139724 proposes a latch position indicator system for remotely determining whether a latch assembly is latched or unlatched.
In the past, when drilling in deepwater with a marine riser, the riser has not been pressurized by mechanical devices during normal operations. The only pressure induced by the rig operator and contained by the riser is that generated by the density of the drilling mud held in the riser (hydrostatic pressure). During some operations, gas can unintentionally enter the riser from the wellbore. If this happens, the gas will move up the riser and expand. As the gas expands, it will displace mud, and the riser will “unload.” This unloading process can be quite violent and can pose a significant fire risk when gas reaches the surface of the floating structure via the bell-nipple at the rig floor.
U.S. Pat. No. 4,626,135 proposes a gas handler annular blowout preventer (BOP) to be installed in the riser. The gas handler annular BOP is activated only when needed, but instead of simply providing a safe flow path for mud and gas away from the rig floor, the gas handler annular BOP can be used to hold limited pressure on the riser to control the riser unloading process. However, drilling must cease because movement of the drill string through the annular BOP when the annular seal is engaged against the drill string will damage or destroy the non-rotatable annular seal. During drilling, the annular BOP's seal is open, and drilling mud and cuttings return to the rig through the annulus or annular space. Ram type blowout preventers have also been proposed in the past for drilling operations, such as proposed in U.S. Pat. Nos. 5,735,502; 4,488,703; 4,508,313; and 4,519,577. As with annular BOPs, drilling must cease when the ram BOP seal is engaged against the drill string tubular or damage to the seal will occur.
Prior to the development of RCDs, packing heads, such as proposed in U.S. Pat. Nos. 2,038,140; 2,124,015; 2,148,844; 2,163,813; and 2,287,205, were used for sealing around the drill string during drilling operations. Unlike an RCD, a packing head has no bearing assembly and its sealing element does not rotate with the drill string or other inserted tubular or oilfield component. U.S. Pat. No. 2,170,915 proposes a stationary stripper rubber seal positioned in a housing over a well casing through which the drill string may be rotated for drilling. A problem with such prior art packing head and stationary stripper rubber devices is that the sealing element can be damaged or destroyed by the heat generated from the friction resisting the movement of the inserted tubular or oilfield component.
Drilling with casing is gaining some acceptance worldwide for addressing certain onshore and offshore problems such as formation instability, lost circulation, fluids control, and troublesome zones. Drilling with casing eliminates the need to continually replace strings of drill pipe during drilling, saving time since the rig is also drilling while casing is being run into the hole. Although drilling with casing currently constitutes only a small part of worldwide drilling activity, drilling with casing is expected to increase in the future.
Drilling with casing is being attempted with increasingly larger casing sizes. While drilling with casing has been used in the past with 9⅝ inch (24.4 cm) diameter casing, it is now being attempted with casing diameters up to 20 inches (50.8 cm). However, the amount of annular space within a riser or housing for positioning an RCD becomes increasing more limited as the casing size gets larger. The RCD has to be sized to accommodate the large casing, and it is often impractical to use a larger riser or housing, particularly in shallow wells or other applications where the larger casing is only needed for relatively short drilling distances, like 100 feet (30.5 m). Drilling with casing may be attempted in the future in certain subsea applications without a marine riser, particularly for drilling relatively short drilling distances.
Testing performed by the inventors reveals that when a 10¾ inch (27.3 cm) diameter casing section is rotated in a prior art stationary stripper rubber sealing element under low pressures of 5 to 10 psi, the prior art sealing element deteriorates and is damaged in about 2 to 10 hours due to heat generated by the frictional resistive forces. When water is applied to the prior art sealing element surfaces not contacting the casing section, the sealing element damage does not occur until about 30 hours. However, when drilling with casing is used in real drilling applications, much longer drilling times are needed.
Circular seal members positioned within grooves, chambers, pockets or receptacles have been used in the past in applications involving rotating shafts. Kalsi Engineering, Inc. of Houston, Tex. and Parker Hannifin, Inc. of Cleveland, Ohio are two manufacturers of such sealing members. U.S. Pat. No. 4,610,319 proposes a circular sealing member for a drill bit application having a wave pattern on the sealing side of the sealing member and positioned within a circular pocket. The sealing member receives lubrication in the pocket from an external lubricant supply system source. U.S. Pat. Nos. 5,230,520; 5,678,829; 5,738,358; 5,873,576; 6,007,105; 6,036,192; 6,109,618; 6,120,036; 6,227,547; 6,315,302; 6,334,619; 6,382,634; 6,494,462; 6,561,520; and 6,685,194 propose circular seals having sealing interfaces with various geometries and disposed within receptacles, grooves, chambers, or pockets. The seal receptacle, groove, chamber or pocket supports and stabilizes the circular seal and may be used to receive lubricant for the seal from an external lubricant supply source.
International Pub. No. WO2008/133523 proposes a packer seal element with at least one channel within the seal for moving a lubricant through the seal. The packer element is positioned around the drill string, and the lubricant, proposed to be oil or grease, is injected from an external source into a port in the side of the packer seal for travel through the channel in the seal. U.S. Pat. No. 3,472,518 proposes a stationary metal housing positioned close to the surface of a drill pipe with the housing inner surface having a series of rings or grooves forming a tortuous path between the outer surface of the drill pipe and the inner surface of the housing. The tortuous path is proposed to provide for a fluid flow that absorbs the pressure drop from the pressure in the annulus around the drill pipe below the housing to atmospheric pressure on the exterior of the housing.
The above discussed U.S. Pat. Nos. 2,038,140; 2,124,015; 2,148,844; 2,163,813; 2,170,915; 2,287,205; 3,472,518; 4,488,703; 4,500,094; 4,508,313; 4,519,577; 4,610,319; 4,626,135; 5,213,158; 5,230,520; 5,647,444; 5,662,181; 5,678,829; 5,735,502; 5,738,358; 5,873,576; 5,901,964; 6,007,105; 6,016,880; 6,036,192; 6,109,618; 6,120,036; 6,138,774; 6,227,547; 6,230,824; 6,315,302; 6,334,619; 6,375,895; 6,382,634; 6,470,975; 6,494,462; 6,547,002; 6,561,520; 6,685,194; 6,913,092; 7,159,669; 7,237,623; 7,258,171; 7,448,454; and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622; 2007/0163784; 2008/0210471; and 2009/0139724; and International Pub. No. WO2008/133523 are all hereby incorporated by reference for all purposes in their entirety.
It would be desirable to drill with a sealed and pressurized mud system without using an RCD. Particularly, it would be desirable to drill using casing with a sealed and pressurized mud system without using an RCD. It would be desirable to drill for relatively short distances using larger casing sizes without an RCD since the annular space surrounding such casing may be limited. It would be desirable to drill with a non-rotating BOP device that would allow drilling to continue with the sealing element sealed without the sealing element becoming damaged or destroyed from the heat and other effects of friction in a relatively short time period. It would also be desirable to drill with a non-rotating BOP device in relatively shallow subsea wells without a marine riser. It would be desirable to use sealing elements in an RCD that would not become damaged or destroyed from the heat and other effects of friction in a relatively short time period when the RCD bearings or other RCD components malfunction in providing sufficient seal element rotation. It would also be desirable to have a sealing element with bi-directional or redundant sealing. It would be desirable to decrease the differential pressure across the lower seal element in a dual seal configuration.